Liquid-rich Shale Reservoirs Research Articles

Initial Occurrence State and Movability Evaluation of the Gulong Shale Oil Reservoir, Songliao Basin

The Qing-1 layer of the Gulong Depression in the northern Songliao Basin is a liquid-rich shale oil reservoir that has the characteristics of nanopores, high maturity, high gas/oil ratio (GOR), etc. The production performance of wells in the Gulong shale oil reservoir shows the characteristics of “single gas production followed by oil-gas production”. It is difficult to analyze the initial occurrence state and movability of fluid in the shale nanopores using conventional methods. In this study, a comprehensive method, including phase behavior analysis, physical experiments, and molecular simulation, was established to analyze the initial occurrence state and movability of fluid in the Gulong shale oil reservoir. The phase state of the fluid was calculated by the equation of state (EOS), considering nano-confinement effects, and the initial occurrence state was quantitatively evaluated by combining two-dimensional nuclear magnetic resonance (NMR) and molecular dynamics simulation. The movable fluid saturation was quantitatively determined by centrifugal experiments. The results show that the condensate gas state was in small pores, while the volatile oil state was in large pores. The occurrence states of oil were mainly adsorbed oil and free oil. The proportion of adsorbed oil in inorganic pores was about 24.4%, while the proportion of absorbed oil in organic pores was about 57.8%. Based on the cutoff value of T2 before and after the centrifuged laboratory experiments, the movable limit of oil was determined to be 4.5 nm, and the movable fluid saturation was about 11%. The research method proposed in this study has important guiding significance for the initial occurrence state and movability evaluation of similar liquid-rich shale reservoirs.

Molecular Insights of Excessive Water Cut during Cyclic Gas Injection in Liquid-Rich Shale Reservoirs: Contributions of Hydrocarbon Condensation and Water Trapping

Summary In a recent pilot test of cyclic gas injection (huff ‘n’ puff) in a Permian shale reservoir, excessive water product was observed, the reason for which remains unclear. In this work, we analyze the mechanisms of gas huff ‘n’ puff processes using molecular dynamics (MD) simulations and explain the reason for the high water-cut phenomenon. We aim to investigate the hydrocarbon-water-rock interactions during the gas injection as well as production within a shale rock in the pore scale. To mimic the heterogeneous pore structure of the shale rock, we have designed a pore system, including a bulk pore, a pore throat, and a dead-end pore. We simulate the distribution of different fluids during the initial equilibrium stage, the primary depletion stage, and the huff ’n’ puff stage. The results show that an excessive amount of water is trapped by the condensation mechanism in the larger pores during the primary depletion stage. The water is then recovered with the injection of working (lean) gases. Moreover, we have analyzed the effect of different injection gases (IGs) and found that carbon dioxide (CO2) yields a higher water cut compared with methane (C1). Moreover, our findings have revealed the trapping mechanisms of hydrocarbon-water mixtures in shale rocks and have highlighted the impacts of pore structures on the recovery of shale reservoirs. As such, we have provided a potential explanation of the observed phenomenon.

Impact of in-situ gas liberation for enhanced oil recovery and CO2 storage in liquid-rich shale reservoirs

ABSTRACT Carbon dioxide injection in shale reservoirs can be beneficial for enhanced oil recovery and CO2 storage scenarios. CO2 mass transfer can be influenced strongly by the in-situ liberation of light oil components from live oil forming a distinct gas phase. This mechanism has been overlooked in the past for studying CO2 and oil interactions in tight formations. In this work, a series of analytical solutions and numerical simulations were developed to identify the effect on EOR by CO2 due to the liberation of a light hydrocarbon gas phase from live oil in shales. The analytical model demonstrated faster diffusion of CO2 in the two-phase system due to the presence of this gas phase. Using numerical approaches, laboratory-scale simulations indicated that in-situ gas formation can increase oil recovery by 35%. At the field-scale, an additional oil recovery of 9.8% could be attained. Also, the CO2 storage capacity of shale formations could be significantly enhanced due to capillary trapping of CO2 in the liberated gas. The results of this study could potentially be used to improve evaluations of the potential of CO2 EOR in shale reservoirs.

Effects of Entrained Hydrocarbon and Organic-Matter Components on Reservoir Quality of Organic-Rich Shales: Implications for “Sweet Spot” Identification and Enhanced-Oil-Recovery Applications in the Duvernay Formation (Canada)

Summary The hydrocarbon (HC)-storage capacity of organic-rich shales depends on porosity and surface area, whereas pore-throat-size distribution and pore-throat-network connectivity control permeability. The pores within the organic matter (OM) of organic-rich shales develop during thermal maturation as different HC phases are generated and expelled from the OM. Organic-rich shales can potentially retain a large proportion of the HCs generated during the diagenesis process. Commercial HC production from liquid-rich shale reservoirs can be achieved using completion technologies such as multistage-fractured horizontal wells. However, the ability of industry to identify “sweet spots” along multistage-fractured horizontal wells for both primary and enhanced oil recovery (EOR) is still hampered by insufficient understanding of the effects of type/content of entrained HC/OM components on reservoir quality. The primary objectives of the current study are therefore to establish an integrated experimental workflow to investigate the effect of entrained HC/OM on storage and transport properties of the organic-rich shales, and to provide examples of that experimental workflow through analyzing a selected sample suite from a prolific shale-oil reservoir (the Duvernay Formation) in western Canada. To accomplish this goal, a comprehensive suite of petrophysical analyses is performed on a diverse sample suite from the Duvernay Formation that differs in OM content (2.8 to 5 wt%; n = 5), before and after sequential pyrolysis by a revised Rock-Eval analysis [extended-slow-heating (ESH) Rock-Eval analysis]. Using the ESH cycle, different HC/OM components can be distinguished more easily and reliably during the pyrolysis process: free light oil (S1ESH; up to 150°C), fluid-like HC residue (FHR) (S2a; 150 to 380°C), and solid bitumen/residual carbon (S2b; 380 to 650°C). The characterization techniques used at each stage are helium pycnometry (grain density, helium porosity); low-pressure gas [nitrogen (N2), carbon dioxide (CO2)] adsorption (LPA) [pore volume (PV), surface area, pore-size distribution (PSD) within micropores, mesopores, and smaller macropores]; crushed-rock gas [helium, CO2, N2] permeability; and rate-of-adsorption (ROA) analysis (CO2, N2). Scanning-electron-microscopy (SEM) analysis is further conducted to verify/support the petrophysical observations. Powder X-ray-diffraction (XRD) analyses were performed on all samples in the “as-received” state and after Stage S2b (thermal pyrolysis up to 650°C) to quantify variations in mineralogical compositions and their possible controls on the evolution of petrophysical properties (i.e., porosity/permeability). Organic petrography was conducted on selected samples to characterize the nature of OM. Compared with the “as-received” state, porosity, permeability, modal-pore-size distribution, and surface-area increase with sequential pyrolysis stages, associated with the expulsion and devolatilization of free light oil and FHR (S2a; up to 380°C). However, the change in petrophysical properties associated with the degradation of solid bitumen/residual carbon (S2b; up to 650°C) is variable and unpredictable. The observed reduction in porosity/permeability values after Stage S2b is likely attributed to the occlusion of PV with solid bitumen/residual carbon degradation (i.e., coking); sample swelling caused by water loss from the lattice structure of clay minerals (i.e., illite); and sample compaction as a result of OM removal from the rock matrix. Among various stages of the ESH Rock-Eval pyrolysis, the petrophysical properties that are measured after Stages S1ESH and S2a, as they are related to the expulsion of the lighter and heavier free-HC compounds from the rock matrix, are expected to be the most important for primary and EOR applications. Quantification of the evolution of reservoir quality with HC generation/expulsion has important implications for identifying petrophysical “sweet spots” within unconventional reservoirs, optimizing stimulation design, and targeting specific zones within the reservoir of interest with the OM content/type amenable to maximizing gas storage/transport during cyclic solvent injection for EOR applications. The integrated experimental workflow proposed herein could be of significant interest to the operators of organic-rich shale/mudstone plays (e.g., the Duvernay) as a screening tool for developing optimized stimulation treatments for improving primary and enhanced HC recovery.

Molecular simulations of oil adsorption and transport behavior in inorganic shale

Oil production from shale has grown dramatically in North America, and has the potential to do so globally. Understanding the adsorption and transport of liquid hydrocarbon through nanopores of inorganic minerals is crucial not only to develop liquid-rich shale reservoirs, but also to grasp oil migration from deeply buried extremely low permeability source rocks. In this work, the adsorption and transport behavior of n-octane (pentane, dodecane) confined in nanoscale dolomite slit pores have been investigated by grand canonical Monte Carlo (GCMC) and molecular dynamics (MD) simulations. The adsorbed phase density, molecular-scale structures at the interface, self-diffusion are then calculated and analyzed by equilibrium molecular dynamics (EMD). The number of adsorption layers is related to the size of pore. Increasing temperature will decrease the amount adsorbed, while pressures have little effect on amount adsorbed. Near the dolomite surface, the n-octane molecules adopt a preferential alignment parallel to the substrate, better packed and diffuse more slowly. Consider three alkanes, the long alkanes (octane, dodecane) are more easily to be adsorbed on dolomite surface. Lastly, the nonequilibrium molecular dynamics (NEMD) have been used to study the pressure-driven flow of n-octane in dolomite slits, flow characterization, viscosity, and slip length are analyzed. A larger driving force will increase slip length, while having only a negligible impact on the effective viscosity of the n-octane.

Physics-Based Fluid-Flow Modeling of Liquids-Rich Shale Reservoirs Using a 3D Three-Phase Multiporosity Numerical-Simulation Model

Summary Production from liquids–rich shale reservoirs in the US and Canada has increased significantly during the past few years. However, a rigorous understanding of shale rocks and fluid flow through them is still limited and remains a challenge. Thus, the objective of our research is developing a 3D physics–based model for simulating fluid flow through these types of multiporosity rocks. This is important given the recent spread of these types of reservoirs throughout the world. Simulation of liquids–rich shale reservoirs is performed with the construction of an original fully implicit 3D multiphase modified black–oil finite–difference numerical formulation, which uses a multiporosity approach as well as diffusion from solid kerogen. The multiporosity system includes adsorbed porosity, organic porosity, inorganic porosity, natural–fracture porosity, and hydraulic–fracture porosity. A numerical model is developed with capabilities to handle dissolved gas in the solid part of the organic matter, adsorption/desorption from the organic pore walls, viscous– and non–Darcy–flow mechanisms (slip flow and Knudsen diffusion), and stress–dependent properties of natural and hydraulic fractures. Examples of simulated results are presented as crossplots of pressure, production rates, and cumulative production vs. time. These plots are used to show the contributions of free gas, adsorbed gas, and dissolved gas to fluid production from liquids–rich shale reservoirs. Results indicate that both desorption and gas diffusion positively affect shale performance. Simulation results demonstrate that not taking into account desorption and diffusion from solid kerogen leads to underestimating production from liquids–rich shale reservoirs. Furthermore, the simulation study shows that long periods of time are required for the effects of these two mechanisms to be manifested. This helps to explain why shales have been produced over long periods of time (several decades), such as in the case of Devonian wells in the Appalachian Basin. The type of 3D simulation model for multiporosity liquids–rich shale reservoirs developed in this paper is not currently available in the literature. The approach implemented in this paper provides a novel and important foundation for simulating complex shale reservoirs.

Investigation of asphaltene-derived formation damage and nano-confinement on the performance of CO2 huff-n-puff in shale oil reservoirs

In this study, the behavior of asphaltene formation and nano-confinement during the CO2 huff-n-puff process in liquid-rich shale reservoirs is investigated. Asphaltene precipitation and deposition in the pore volume of shale formation from mixing between oil and CO2 could cause formation damage, which reduces the permeability and/or changes the rock surface condition toward more oil-wet. In addition, the nano-confinement effect changes the phase behavior of the fluid affecting the asphaltene formation in tight shale formations. With the development of a reservoir simulation model that incorporates both asphaltene formation and the nano-confinement effect, this study quantifies the effects of asphaltene deposition and nano-confinement on shale oil production of CO2 huff-n-puff.While ignoring the permeability reduction and wettability alteration due to asphaltene deposition, the nano-confinement effect increases the shale oil production by up to 42% during the CO2 huff-n-puff process. However, the nano-confinement effect increases the asphaltene precipitation and deposition in nano-scaled tight formation. On incorporating the formation damage due to asphaltene deposition, more deposited asphaltene due to nano-confinement effect decreases the oil production by 4%. This study clarifies that the effects of asphaltene formation and nano-confinement should be taken into consideration for an accurate prediction of hydrocarbon production during CO2 huff-n-puff in tight shale formation.

Incorporation of multi-phase solubility and molecular diffusion in a geochemical evaluation of the CO2 huff-n-puff process in liquid-rich shale reservoirs

Despite the development of horizontal well and hydraulic fracturing technologies, natural depletion is limited in low productivity, and thereby considerable hydrocarbon remains in low permeable shale reservoirs. Recent researches proved that the deployment of CO2 huff-puff process could extract the remained hydrocarbon. They quantified various mechanisms behind the process and proposed the potential for CO2 sequestration in the shale formation. However, thorough understanding of fluid transport in the CO2 huff-n-puff process has not been completed due to complexity in tight shale formations. They had a lack to analyze potential factors affecting fluid flow in the system of oil/CO2/brine/shale formation: 1) aqueous solubility; 2) molecular diffusion in aqueous and oleic phases; and 3) geochemistry. Therefore, this study diagnoses the potential factors affecting fluid flow during CO2 huff-n-puff process in the shale oil reservoirs. Then, their effects are quantified by analyzing shale oil recovery and CO2 storage capacity.Since a fraction of injected CO2 dissolves in water and oil during the CO2 huff-n-puff process, transportability is acquired by molecular diffusion in aqueous and oleic phases. In addition, dissolution of CO2 changes the pH of in-situ brine, which is a sensitive factor in geochemistry, and thereby would change physical properties of formation. Implementing these mechanisms, this study simulates the CO2 huff-n-puff process in shale oil reservoirs. It is observed that effects of aqueous solubility and geochemistry decrease oil production by 3.2% and 6%, respectively. Approximately, up to 9.5% of CO2 to be injected is sequestrated in depleted shale formation via solubility mechanism. Molecular diffusion in oleic phase increases the oil production by 2%, but that in aqueous phase is negligible. For the accurate estimation of oil production and CO2 storage capacity in the simulation of CO2 huff-n-puff process for shale oil reservoir, the comprehensive model should consider potential factors such as aqueous solubility, molecular diffusion, and geochemical reactions. Because the potential factors have been neglected in the works of other types of shale reservoirs, the proposed approaches expect to expand our understanding in the CO2 injection to tight and shale gas/oil reservoirs.

Effects of aqueous solubility and molecular diffusion on CO2-enhanced hydrocarbon recovery and storage from liquid-rich shale reservoirs

ABSTRACTThis study investigates the effects of aqueous solubility and aqueous molecular diffusion of gaseous components (CO2 and CH4) on the CO2 huff and puff process in the liquid-rich shale reservoirs. In a gas-condensate reservoir, the effects negligibly enhance the hydrocarbon production, but increase the CO2 storage with 4.4% by solubility trapping. In a shale oil reservoir, they increase the production and CO2 storage up to 5% and 14% by more CO2 imbibition and contacting between CO2 and oil. This study clarifies the importance of aqueous solubility and aqueous-phase molecular diffusion of CO2 huff and puff in shale reservoirs.

Principal components methodology – A novel approach to forecasting production from liquid-rich shale (LRS) reservoirs

Abstract With increasing global demand for energy, the importance of unconventional shale oil and gas research cannot be over-emphasized. The oil and gas industry requires rapid and reliable means of forecasting production. Existing traditional decline curve analysis (DCA) methods have been limited in their ability to satisfactorily forecast production from unconventional liquid-rich shale (LRS) reservoirs. This is due to several causes ranging from the complicated production mechanisms to the ultra-low permeability in shales. The use of hybrid (combination) DCA models can improve results. However, complexities associated with these techniques can still make their application quite tedious without proper diagnostic plots, correct use of model parameters and some knowledge of the production mechanisms involved. This work, therefore, presents a new statistical data-driven approach of forecasting production from LRS reservoirs called the Principal Components Methodology (PCM). PCM is a technique that bypasses a lot of the difficulties associated with existing methods of forecasting and forecasts production with reasonable certainty. PCM is a data-driven method of forecasting based on the statistical technique of principal components analysis (PCA). In our study, we simulated production of fluids with different compositions for 30 years with the aid of a commercial compositional simulator. We then applied the Principal Components Methodology (PCM) to the production data from several representative wells by using Singular Value Decomposition (SVD) to calculate the principal components. These principal components were then used to forecast oil production from wells with production histories ranging from 0.5 to 3 years, and the results were compared to simulated data. Application of the PCM to field data is also included in this work. This study provides fresh initiatives into how production forecasting from unconventional LRS reservoirs can be done in a different way.

Further Investigation of Effects of Injection Pressure and Imbibition Water on CO2 Huff-n-Puff Performance in Liquid-Rich Shale Reservoirs

Shale oil production has increased rapidly in the past decades, especially in the United States, and results in a revolution in the energy landscape. However, one main problem existing in the shale reservoir development is the sharp decline of liquids production in all the hydraulically fractured wells. In recent years, CO2 huff-n-puff injection has been proved to be a potential method to enhance the oil recovery. In this study, the effects of injection pressure and imbibition water on CO2 huff-n-puff performance were further investigated. Eagle Ford core samples and Wolfcamp dead oil were used in this experimental study. The microscopic pore characteristics of Eagle Ford shale core samples were analyzed, and the results show that 98.08% of the pore sizes are distributed between 3 nm and 50 nm. The experimental results demonstrate the great potential of CO2 huff-n-puff EOR. The cumulative oil recovery can reach 68% after seven huff-n-puff cycles. The oil recovered in each cycle deceases as injection cycle...

Low-salinity water and surfactants for hydraulic fracturing and EOR of shales

There are significant recoverable oil and gas resources stored in shale reservoirs throughout the world. Horizontal well with multistage hydraulic fracturing is an enabling technology for economic production of these shale resources. Recovery factors of liquid rich shale reservoirs is typically less than 10%, hence, there is an incentive for implementing enhanced oil recovery (EOR) technologies to improve oil production from these very tight reservoirs. Brine, chemical (surfactant), gas, or combination of these fluids imbibition or injection in huff-n-puff scenario could improve oil recovery of liquid rich shale reservoirs. In this study, low-salinity water and low-salinity water + surfactant imbibition are assessed as both hydraulic fracturing and EOR fluids in liquid rich shale reservoirs. Osmosis, capillary pressure, wettability alteration, and other effects are among the mechanisms by which these fluids can improve oil recovery from shale reservoirs. These favorable effects were investigated through imbibition experiments. Experiments show: (a) low-salinity water huff-n-puff in tight formations can improve oil production from tight formations. This is because wettability alteration, capillary, and osmotic forces; (b) surfactant + low-salinity-water huff-n-puff can further improve oil production due to additional IFT decrease and wettability alteration by surfactants; hence, improve oil production from stimulated ultra-tight formations. Based on experimental observations and literature reviewed, low-salinity water huff-n-puff (until economical), followed by low-salinity water + surfactant huff-n-puff EOR process is recommended to optimize production from liquid rich shale reservoirs, while minimizing cost. These fluids can be used to reduce matrix-fracture skin damage. The effectiveness of these hydraulic fracturing and EOR fluids in shales is highly dependent on the existence and extent of natural fractures or laminations within the stimulated reservoir volume; this is because osmosis and diffusion are very slow processes.

Unique Mixtures of Anionic/Cationic Surfactants: A New Approach To Enhance Surfactant Performance in Liquids-Rich Shale Reservoirs

Summary Surfactants are important components in fracturing fluids for helping ensure higher productivity from unconventional reservoirs. Conventional wisdom suggests that surfactant mixtures generally exhibit better performance than individual surfactants. In addition, the synergism between surfactants increases with the degree of charge difference. Some current commercial surfactants were formulated by mixing nonionic and anionic surfactants (Sn/a), but few were formulated by mixing anionic and cationic (Sa/c) surfactants because of the risk of precipitation or formulation instability. This paper discusses binary mixtures of Sa/c surfactants prepared with different mole ratios to determine their synergisms; mixtures of nonionic/anionic (Sn/a) and nonionic/cationic (Sn/c) surfactants are also compared. Surface/interfacial properties [maximum surface excess concentration (Γmax), minimum molecular area (Amin), critical micelle concentration (CMC), and Gibbs free energy (ΔG)] and interaction parameters (βm and βs) in both the mixed micelle and interface were quantified to demonstrate the synergistic effect between various surfactants. In addition, the potential application of these mixtures for unconventional treatments was examined with regard to emulsion behavior and column-packed oil-recovery testing. The results for the Sa/c surfactant mixtures show that, compared with the parent species, Γmax of the Sa/c system is approximately one order of magnitude higher (corresponding to one order of magnitude lower in Amin). The resultant CMC is approximately two orders of magnitude lower than that of the parent species, and the ΔG of Sa/c is more negative. Notably, the interaction parameters further indicate that strong synergism exists for the Sa/c system at various mole ratios in both mixed micelle and monolayers at the interface (with an optimized ratio at 2:3), whereas for the Sn/a system, weak synergism was identified in the mixed micelle at the mole ratio of 3:2. No synergism was observed for the Sn/c system. In addition, phase-behavior testing indicated that a weak emulsion was formed in the presence of the Sa/c by use of Eagle Ford crude oil. Column-flooding testing also revealed improved oil recovery of the Sa/c system compared with individual species. The synergistic effect between Sa/c surfactant mixtures, as well as the laboratory results of the emulsion behavior and oil recovery, suggests a new practice for applying Sa/c surfactant blends for unconventional applications.

Reservoir and fluid characterization of a tight gas condensate well in the Montney Formation using recombination of separator samples and black oil history matching

Liquid-rich shale (LRS) reservoirs are economically attractive but operationally challenging particularly for cases where multi-phase flow occurs within the reservoir. Proper treatment of PVT and rock properties, as well as rock-fluid interaction, in these unconventional reservoirs is central to providing improved short- and long-term oil and gas production forecasts. In the presence of limited surface sampling, the available analytical models often do not provide satisfactory results due to the uncertainty in the initial in-situ fluid system. In such situations, and particularly when there are many unknown parameters, numerical models are ideally suited, using a history matching framework, to assist with reservoir and fluid characterization.In this paper, production data from a multi-fractured horizontal well completed in a tight gas condensate reservoir in the Montney Formation in western Alberta, Canada is presented and analyzed using black oil numerical simulation. An assisted history-matching routine (i.e. Differential Evolution (DE) algorithm) is used in combination with black oil numerical simulations to characterize reservoir fluids and estimate reservoir and hydraulic fracture properties. The applicability of black oil numerical simulation for accurate prediction of the fluid model and well performance using numerous compositional numerical simulations and various fluid systems is first verified. The in-situ fluid is assumed to be a mixture of recombined separator samples with unknown oil-gas recombination ratio. The effect of time of sampling on the produced well stream composition is considered.Our results show that recombined separator sample mixtures collected early on during production of wells subjected to limited drawdown can successfully represent reservoir fluid properties with the exception of saturation pressure. In other words, the reservoir fluid PVT behavior can be predicted by recombination of an early initial separator fluid sample only by varying the saturation pressure. Hence, the assisted history matching can be performed using black oil numerical simulations with a reduced number of unknowns for the fluid system. The well/reservoir properties and unknown reservoir fluid are characterized in terms of a 12-parameter system. The history-matched results using DE could satisfactorily reproduce the water and hydrocarbon surface flow rates, and flowing bottomhole pressure curves. The quality of results are comparable to those obtained previously (Hamdi et al., 2015) using a fully-compositional numerical model.The new workflow using assisted history-matching combined with black oil simulation provides a practical yet accurate method for characterizing fluid, reservoir and fracture properties in unconventional gas condensate systems.

Enhanced Oil Recovery in Liquid–Rich Shale Reservoirs: Laboratory to Field

Summary Production of tight oil from shale reservoirs in North America reduces oil imports and has better economics than natural gas. Currently, there is a strong interest in oil production from Bakken, Eagle Ford, Niobrara, and other tight formations. However, oil-recovery fraction for Bakken remains low, which is approximately 4–6% of the oil in place. Even with this low oil-recovery fraction, a recent United States Geological Survey study stated that the Bakken and Three Forks recoverable reserves are estimated to be 7.4 billion bbl; thus, a large volume of oil will remain unrecovered, which was the motivation to investigate the feasibility of enhanced oil recovery (EOR) in liquid-rich shale reservoirs such as Bakken. In this paper, we will present both laboratory and numerical modeling of EOR in Bakken cores by use of carbon dioxide (CO2), methane/ethane-solvent mixture (C1/C2), and nitrogen (N2). The laboratory experiments were conducted at the Energy and Environmental Research Center (EERC). The experiments recovered 90+% oil from several Middle Bakken cores and nearly 40% from Lower Bakken cores. To decipher the oil-recovery mechanisms in the experiments, a numerical compositional model was constructed to match laboratory-oil-recovery results. We concluded that solvent injection mobilizes matrix oil by miscible mixing and solvent extraction in a narrow region near the fracture/matrix interface, thus promoting countercurrent flow of oil from the matrix instead of oil displacement through the matrix. Specifically, compositional-modeling results indicate that the main oil-recovery mechanism is miscible oil extraction at the matrix/fracture interface region. However, the controlling factors include repressurization, oil swelling, viscosity and interfacial-tension (IFT) reduction, diffusion/advection mass transfer, and wettability alteration. We scaled up laboratory results to field applications by means of a compositional numerical model. For field applications, we resorted to the huff ’n’ puff protocol to assess the EOR potential for a North Dakota Middle Bakken well. We concluded that long soak times yield only a small amount of additional oil compared with short soak times, and reinjecting wet gas, composed of C1, C2, C3, and C4+, produces nearly as much oil as CO2 injection.

Forecasting production of liquid rich shale (LRS) reservoirs using simple models

Due to the advent of shale reservoirs as important sources of oil and gas production, there has been a critical need for reliable techniques for forecasting production and estimating reserves from these plays. This work presents the results of a study to determine whether simple decline models can be used to forecast production and estimate reserves of both oil and gas in liquid rich shale (LRS) reservoirs with reasonable accuracy. We found that hybrid models (i.e., one model such as the Duong model for transient flow coupled with a different model, such as the Arps hyperbolic model with an appropriate value of the parameter “b”) are appropriate for forecasting oil production and that it is possible to forecast solution gas production with availability of adequate data.To establish the “truth case” for comparison, we simulated production with four different reservoir fluids using a commercial compositional reservoir simulator. We tested a variety of hybrid and simple DCA models on simulated data (and later on field data) with a work flow that included identifying flow regimes with diagnostic plots for each fluid sample. We analyzed 0.5–3 years of production history to estimate model parameters for forecasting future production. Also, we forecasted gas production using a technique similar to one recently presented in the literature.Lengthy transition periods between transient linear flow and boundary dominated flow (BDF) were observed on the diagnostic plots. This is presumably due to multi-phase flow effects, as this transition period is typically much shorter in single-phase shale reservoirs. As in single-phase flow, the Arps decline model proved to be good for forecasting in the BDF regime. For transient flow, we examined the Duong model (which includes transient linear flow as a special case) and YM-SEPD (modified form of Stretched Exponential Production Decline model). In some cases, we applied the Arps model for both the transition period and BDF regimes (with different b values). We concluded that hybrid DCA models are more appropriate for multi-phase flow analysis than simple DCA models. In most of the cases, the hybrid YM-SEPD and Arps models led to more accurate oil production forecasts than other alternatives. Our analyses of solution gas forecasts indicated that solution gas production forecasting is possible but there is still need for more research in this area.

Potential of Improving Oil Recovery with Surfactant Additives to Completion Fluids for the Bakken

Fracture treatment performance in Bakken liquid-rich shale reservoirs can be improved by altering rock wettability from oil-wet to water-wet. The use of surfactant additives for altering wettability also results in alteration of the interfacial tension (IFT). The Young–Laplace equation relates the capillary pressure to IFT and contact angle. Thus, it follows that capillarity is significant in nanopores associated with unconventional liquid reservoirs (ULRs) and complex as the contact angle (CA) and IFT varies simultaneously. This study carefully evaluates these interactive variables and compares the performance of anionic, nonionic, blended, and complex nanofluid (CnF) surfactants in recovering liquid hydrocarbon from siliceous and carbonate Bakken shale cores through spontaneous imbibition experiments. In addition, we also analyze the effect of wettability, surfactant adsorption, and IFT alteration on the process. CA measurement is used in determining the original wettability of Bakken cores, as well as ...

Numerical analysis of cyclic CH4 injection in liquid-rich shale reservoirs based on the experiments using different-diameter shale cores and crude oil

In this paper, the potential to enhance oil recovery (EOR) by CH4 gas injection in shale reservoirs is investigated through numerical analysis based on the experiments using different-diameter shale cores and crude oil. The cores used in these experiments had the same length of 2 inches and six different diameters of 1, 1.5, 2, 3, 3.5 and 4 inches. The crude oil from Wolfcamp was used to saturate the shale core plugs. A Gas Chromatography/Mass Spectrometer (GC/MS) instrument and Xcalibur software were used to analyze the crude oil components.The experiments were history-matched using numerical simulation models. The calibrated numerical models were then employed to perform a series of sensitivity studies to investigate the effects of operation parameters on oil recovery in shale oil cores, such as the number of injection cycles, molecular diffusion, soaking time, and operation schedule. The experimental results show that oil recovery factor is smaller from a larger core than that from a smaller core due to the decline of surface area per volume and the drop of pressure gradient along the diameter. The simulation results show that incremental oil recovery in each of the subsequent cycle decreases as the number of injection cycles increases. In terms of EOR mechanisms, viscous displacement and relative permeability hysteresis may be important, while molecular diffusion does not seem to play an important role after the first five cycles. For the soaking time, a larger core needs a longer soaking time to achieve the maximized oil recovery than a smaller core within a single cycle. Within a fixed elapse time, a shorter soaking time results in higher oil recovery. This work provides a fundamental understanding of the key parameters that control cyclic CH4 injection to enhance oil recovery in shale rocks.

Statistical, Data-Driven Approach to Forecasting Production from Liquid-Rich Shale Reservoirs

The oil and gas industry needs fast and simple techniques of forecasting oil and gas production. Forecasting production from unconventional, low permeability reservoirs is particularly challenging. As a contribution to the continuing efforts of finding solutions to this problem, this paper studies the use of a statistical, data-driven method of forecasting production from liquid-rich shale (LRS) reservoirs called the Principal Components Methodology (PCM). In this study, production of five different highly volatile and near-critical oil wells was simulated for 30 years with the aid of a commercial compositional simulator. Principal Components Methodology (PCM) was applied to production data from the representative wells by using Singular Value Decomposition (SVD) to calculate the principal components (PCs). These principal components were then used to forecast oil and solution gas production from the near-critical oil wells with production histories ranging from 0.5 to 2 years, and the results were compared to simulated data and the Modified Arps’ decline model forecasts. Application of the PCM to field data is also included in this work. Various factors ranging from ultra-low permeability to multi-phase flow effects have plagued the mission of forecasting production from liquid rich shale reservoirs. Traditional decline curve analysis (DCA) methods have not been completely adequate for estimating production from shale reservoirs. The PCM method enables us to obtain the production decline structure that best captures the variance in the data from the representative wells considered. This technique eliminates the need for parameters like the hyperbolic decline exponents (b values) and the task of switching from one DCA model to another. Also, production forecasting can be done without necessarily using diagnostic plots. With PCM, production could be forecasted from liquid-rich shale reservoirs with reasonable certainty. This study presents an innovative and simple method of forecasting production from liquid-rich shale (LRS) reservoirs. It provides fresh insights into how estimating production can be done in a different way.

Technology Focus: Field Development Projects

Technology Focus The low price of oil has had an immediate effect in the planning departments of oil companies. They were forced to shift the focus and carefully rank and select only those developments that would ensure profitability in the production of oil and gas. Hence, the field-development projects need to include and consider not only a static or dynamic subsurface characterization but also the production-systems and facilities options, to trigger profitability and establish clear breakeven thresholds. More than ever, the consideration of deep water, tight reservoirs, shale oil, remote locations, or environmentally critical plays is placed under the microscope. Increasingly difficult project economics has delayed or stopped investments that were estimated to be safe and profitable before the price drop. In this extended-low-oil-price framework, a positive economic return is actively sought by ever-incremental integration of subsurface and surface engineering, to select strategies that lower the production cost. I would like to mention that some of the key elements that enabled better economics in the most successful projects were new project designs that ensure flexibility; synergies with contractors, especially for supply-chain improvements; alliances; and inclusiveness of breakthrough technology. Additionally, a new trend in field development that has proved to be beneficial and that assesses profitability of production strategies is the incorporation of pilot or early- or initial-production units to establish real project economics and boost opportunities for understanding the cost-reduction opportunities. This is a strategy incrementally applied globally by international and national oil companies. The complexities of the development plans have propelled an integration among professionals of subsurface studies, production systems, construction engineering, transportation, and even marketing teams, to an increased collaboration not seen before. The three papers selected for this feature typify this necessary integrated approach in field developments. In these papers, as well as in those suggested for additional reading, the main factor is the integration of all elements involved in ensuring economic profitability, including subsurface studies, drilling and completion, construction engineering, production systems, technology, environmental considerations, global supply and construction integration, compliance with government regulations, synergy with contractors and shareholders, consideration of other projects’ supply chains in nearby fields, contract strategies, and even weather. Remarkably, the academic, theoretical, modeling, and research studies have also shifted toward assessing the optimal or economic development of shale oil and gas, offshore fields, and environmentally protected areas, marking an alignment within the industry to solve the current concerns and incorporating in the studies a very practical engineering or economic approach not frequently present before. That all the optimizations, synergies, and successes presented in the papers you will read are flourishing now is not coincidental but clearly is a result imposed by the hard times derived from the low price of oil and the accelerated pace with which we want to produce our resources. An extended-low-price era seems to have settled in, and, even if in the future 3 to 4 years the price of oil rises, the new field-development-optimization strategies we are testing and applying now will serve our industry well, optimizing and lowering the break-even thresholds for the huge resources we still need to produce worldwide. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 178191 Cluster Wells Applied in Wetland Environment in North Azadegan by Bingshan Liu, CNPC Drilling Research Institute, et al. SPE 177204 Defining the Optimum Exploitation Strategy Combining Water Injection, Field Development, and Artificial- Lift Analysis to a Mature Field Through Surface and Subsurface Coupled Models by O. Espinola, Schlumberger, et al. SPE 175531 Effect of Well Spacing on Productivity of Liquid-Rich Shale Reservoirs With Multiphase Flow: A Simulation Study by A. Khanal, University of Houston, et al.